Search
`
November 14, 2024

Posted on

Ott Restructures PJM Divisions, Leadership

PJM CEO Andy Ott on Friday announced organizational changes that will give additional responsibilities to senior vice presidents Stu Bresler and Vince Duane — a move Ott had foreshadowed following the departure of Executive Vice President and Chief Operations Officer Mike Kormos in March.

Bresler, who has been overseeing the Markets Division, will add the Operations Division, formerly overseen by Kormos, to his duties. Vice President Mike Bryson will continue to lead Operations.

pjm, andy ott

The newly formed Law, Compliance and External Relations Division will report to Duane, the RTO’s general counsel, and include the State & Member Services Division and the Compliance Division, which already had been moved under Duane’s supervision earlier this year. Vice President Denise Foster will continue to lead State & Member Services.

The new division will address legal and regulatory components and oversee communications with various audiences.

“We are making some changes to our structure as our organization continues to grow and evolve,” Ott said. “Our objective with this realignment is to better serve our stakeholders by positioning internal processes — and those conducting them — to better support company strategies.”

The changes will take effect July 6.

Ott was named CEO in October after a six-month transition period at the side of Terry Boston, who retired. (See Boston Retirement Prompts Additional Promotions at PJM).

When PJM announced Kormos’ departure, Ott had said that his position would not be filled. (See PJM COO Kormos Leaving; Post Won’t be Filled.)

— Suzanne Herel

Posted on

New York Debates PPAs or RECs for Clean Energy

By William Opalka

New York policymakers grappled last week to find the most cost-effective way to reach the state’s 50% renewable energy target by 2030 while maintaining a competitive electricity market.

NY State Wind FarmThe New York Public Service Commission held a technical conference June 9 to discuss the state’s proposed Clean Energy Standard, the roadmap intended to transition the state away from fossil fuel — and eventually nuclear — generation (15-E-0302).

“Without question, thinking about how we are going to get new resources into our mix is key to our success,” PSC Chair Audrey Zibelman said.

At the conference, industry stakeholders debated whether power purchase agreements, renewable energy credits or some combination of both would be the best way to achieve renewable goals without exposing consumers to price risks in an environment of low natural gas prices. The state is moving away from the current centralized procurement by the New York State Energy and Research Development Authority.

Under both the PPA and REC approaches, the total payment per megawatt-hour, including energy and capacity, would be set at the start of the project. Under fixed-price RECs, the generator would be exposed to fluctuations in commodity value (energy and capacity revenue).

Under a bundled PPA, ratepayers would accept commodity price risk, with the net program cost determined based on the difference between the PPA and energy and capacity values. “Where at any point in time the value of energy/capacity exceeds the contracted PPA amount, the program cost per megawatt-hour becomes negative (i.e., [load-serving entity] customers benefit from paying the renewable electricity generator less than the market value of energy and capacity),” explained the PSC staff’s cost study, which was released in April.

The study assumed PPAs and RECs would be used equally to procure the 5.2 GW of Tier 1 renewables envisioned by 2023. Those resources would be dominated by land-based wind (38%) and solar power developed under the NY-Sun initiative (52%). The remainder would be supplied by utility scale solar, bioenergy, hydropower, imports and offshore wind. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)

New York currently has about 2.5 GW of renewables: almost 2,000 MW of wind resources and 500 MW of solar.

Gavin Donohue, president of the Independent Power Producers of New York, said the REC-only approach is what brought the state to its current level of success. “It takes the risk away from ratepayers and puts it solely on … the generator sector,” he said. “We feel very strongly that if it’s not broke, don’t fix it.”

Donahue said long-term fixed contracts wouldn’t permit consumers to benefit from innovations that might lower power prices.

“The PPAs don’t reflect the changes over the long term in the marketplace,” he said.

Anne Reynolds, executive director of the Alliance for Clean Energy New York, said developers who belong to her group say the current REC model has limitations.

“Yes, the REC-only approach has gotten us a good deal of renewables built, but if you look at the pace of what we’ve accomplished over the past 10 years, it is not enough to get us to 50%,” she said.

“We think the way to do that is to attract the maximum number of developers we can to New York so that you get a robust lineup of projects and you get good competition.”

Consumers would benefit from long-term low prices and generation that doesn’t rely on fossil fuels, she said.

 

Posted on

Tomorrow’s Grid is Here — Almost

By Rich Heidorn Jr.

WASHINGTON — A standing-room-only crowd got a glimpse of the grid of the future — and what’s keeping us from getting there — at last week’s Energy Bar Association Annual Meeting.

Woolf © RTO Insider - future grid energy bar association conference
Woolf © RTO Insider

The session was titled “Tomorrow’s Grid is Here.” But in their description of the technical, regulatory and behavioral obstacles, some members of the panel seemed to want to add the word “almost.”

“Electricity is a public good. Yet the system we’ve got is going through a huge transformation and from my perspective there’s no one at the helm,” said Malcolm Woolf, former head of the Maryland Energy Administration who is now senior vice president with Advanced Energy Economy, a national business association.

“Utilities are doing exactly what they’re supposed to do based on historic incentives, but those may not be right for what we want today. The federal government is largely deferring to the states … and the states don’t really have the capacity to drive this. They don’t really know what they want.

“With the exception of a few states like New York and maybe California and Hawaii … I don’t think those conversations are going on.”

Not an Extension Cord

Pesin © RTO Insider - future grid energy bar association conference
Pesin © RTO Insider

Woolf said policymakers need to stop thinking of the grid as “a long extension cord” with centralized generation and one-way power flow to a “market-maker network … where you’ve got a lot of distributed generation, a lot of centralized generation, all integrating to help our reliability and resiliency.”

Corporate America has moved more quickly than regulators, Woolf said. “Sixty percent of the Fortune 500 have renewable and climate goals, yet it’s only a handful that are going to be able to do deals because in most of the country it’s really hard to do deals. In North Carolina, the SolarCity — solar leasing — model is not legal. In Maine [and] still vertically integrated states, you can’t do offsite [power purchase agreements]. Talk to eBay who passed an offsite PPA bill three or four years ago in Utah and still hasn’t been able to get the project up and running.

The “MGM [Grand hotel and casino] in Vegas has just decided to go off grid and pay a massive $80 million penalty to NV Energy because they just want to self-generate,” he continued. “There’s a whole array of state barriers because no one thought that business wanted their own solution.”

Terry © RTO Insider - future grid energy bar association conference
Terry © RTO Insider

Among the speakers was Deputy U.S. Assistant Energy Secretary Michael Pesin, who described the “three-legged stool” of research and development: technology, policy and markets. Rudolph G. Terry, director of the Philadelphia Industrial Development Corp., gave a presentation on the conversion of the Philadelphia Navy Yard from a defense installation to an urban industrial campus with its own microgrid.

Providing the utility perspective was Robert Stewart, manager of smart grid and technology for Pepco Holdings Inc.

Pepco has 26,000 net metering customers (360 MW of solar capacity) and is receiving 1,000 applications a month. It can’t accept them in some rural areas of New Jersey served by 12-kV lines. “We have five feeders that were closed [to new solar],” he said, adding that technical fixes will allow at least some to reopen eventually.

Impact of Electric Vehicles

Stewart © RTO Insider - future grid energy bar association conference
Stewart © RTO Insider

Stewart also talked about the potential impact of electric vehicles, and how to make them practical for low-income drivers who could benefit from their low maintenance and operating costs.

“The problem is most of these people live in multi-dwelling units. They can’t have their own charger. So rather than try and solve the issue with multi-dwelling units, if you gave them access to a charge someplace else — workplace charging through DC direct fast charge, [or] they stop and get a cup of coffee [and] top it off — it’s more like an appliance to them.”

Pepco faces another challenge in older, wealthier suburbs with high concentrations of EVs, such as Maryland’s Montgomery and Prince George’s counties. Because EVs draw about half the power of a full home load, such areas are at risk of overloading their transformers, Stewart said.

Based on a pilot program, Pepco believes most EV drivers will plug in between 4 and 8 p.m., increasing the afternoon peak load.

The company hopes to spread the load through time-of-use rates, which Stewart said could save the owner of a Nissan Leaf $300 a year. But utilities have a hard time making their case, he said.

“Even though you sit there with the numbers and you try to prove to them all you have to do is not charge between noon and 8 p.m. and you get [savings], the customer still is not with you,” he said. “They think there’s something behind the scenes. It’s too good to be true and the utility is really just trying to rip them off.”

Posted on

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — The PJM Market Implementation Committee will hold a special meeting June 29 to continue discussion about the process for approving fuel cost policies and redefining terms, including “market seller.”

The changes, which stem from an annual review of Manual 15, were on the MIC’s agenda for endorsement Wednesday, but after spending one and a half hours talking about them, members asked to continue to work the issue.

One of the topics of discussion was new language added to clarify that the “market seller is the entity that submits a cost-based offer and is responsible for maintaining all information necessary to calculate resource’s cost-based offer.”

Members said they wanted to make sure that any new definitions were consistent with the Tariff.

Catherine Mooney of Monitoring Analytics also proposed language changes on behalf of the Independent Market Monitor.

“The purpose of Manual 15 is to develop the primary input for market power mitigation. This is one of the Market Monitor’s primary responsibilities,” she said.

In a case where a market seller is an agent of the generation owner, it needs to have access to all of the information required to not only calculate but also support a cost-based offer, she said.

Mooney also introduced language that would clarify the Monitor’s authority in evaluating fuel cost policies.

More Flexible Parameter Limited Exception Process Approved

The committee, with two abstentions, endorsed a proposal to make the parameter limited schedule exception process more flexible.

“The most important goal is to solve the problem of inflexibility,” PJM’s Tong Zhao said. (See “Manual Changes to Detail Unit-Specific Operating Parameter Adjustment Process under CP,” PJM Operating Committee Briefs.)

The revisions allow generators to request an exception if they learn of a need after the Feb. 28 deadline. They also permit a temporary exception to be extended to a period or a persistent exception if the need arises after the deadline.

In addition, the changes give PJM and the Monitor more time to review requests and give their determinations to market sellers.

Retroactive Black Start Billing Charges Focus of Proposed Study

PJM’s Tom Hauske introduced a problem statement and issue charge designed to mitigate the potential for large, retroactive black start charges.

Currently, the Tariff does not address when the Monitor will review the costs for new units entering black start service outside of the annual revenue recalculation period.

A number of new units have recently entered black start service, many replacing retiring units. To ensure PJM had sufficient resources, most of these new units entered service before their initial capital costs and annual revenue requirements were approved by the Monitor — some with a lag of six months or longer.

pjm market implementation committee

That resulted in significant charges to load in April.

“We would all benefit from more transparency. … If you have these things under review for a period of time and they’re accumulating charges, we’d like to see how large that accumulation might be,” said Jeff Whitehead of Direct Energy. “If we could minimize it, that would be good. If we can’t, we need to at least understand what the liability is going to be.”

“The back charges were a shock to our members and clients,” added Carl Johnson of the PJM Public Power Coalition. “Even if we don’t know what the scope of that is going to be, just knowing it exists is helpful.”

“There are more coming,” Hauske replied. “We can come up with an estimate.”

Conference Call Set to Discuss Auction-Specific Bilateral Transactions

A special MIC conference call will be held June 24 to discuss proposed clarifications to auction-specific bilateral transactions.

Assistant General Counsel Jen Tribulski said the changes aim to preserve the physicality of the transactions and ensure members’ indemnification.

The new rules assign auction credits and bonus payments to the buyer, while the seller retains the obligation to perform. (See “PJM Proposes Clarifications to Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

Members said they wanted more information on the clarifications.

Committee Endorses Two Problem Statements from Members

With little discussion, the committee unanimously approved:

— Suzanne Herel

Posted on

SPP Seams Steering Committee Briefs

SPP and MISO have ended months of uncertainty by agreeing to a second joint system study, which will take a “targeted” look at the two entities’ newly created Integrated System seam in the Upper Midwest.

SPP's Seams with MISO (ACES) SPP staff told the Seams Steering Committee, which met in Dallas on June 8, that the MISO members of the Interregional Planning Stakeholder Advisory Committee (IPSAC) voted last month to pursue the study. The Joint Planning Committee, composed of SPP’s David Kelley, director of interregional relations, and MISO’s Eric Thoms, manager of planning coordination and strategy, made it official May 31 when the two agreed to begin the study.

The RTOs conducted their first joint study last year, identifying three potential interregional transmission projects. However, they were unable to reach agreement on pursuing any of them. (See SPP, MISO Conclude Joint Study Empty-Handed.)

SPP’s interregional coordinator, Adam Bell, said both staffs have begun discussions on the study’s scope. He said the staffs are planning to discuss the draft scope at a possible IPSAC meeting in July and hopes to wrap up the study in the first quarter of 2017.

Kelley told the committee both staffs have a “desire” to do a larger study, but they are constrained by lack of manpower.

Bell said SPP will continue discussions with MISO to incorporate process improvements identified by stakeholders during the IPSAC’s March meeting.

SPP also is conducting a joint study with Associated Electric Cooperative Inc. (See SPP, AECI Endorse Scope for 2016 Joint Planning Study.)

Staff told the committee the study is focused on five “target areas” in AECI’s footprint where there have been recurring operational problems:

  • Northeast Oklahoma (potential overloads, voltage issues);
  • Southwest Missouri (potential overloads, voltage issues);
  • Central Missouri (potential low-voltage issues);
  • Wheaton area, southwest Missouri (potential upgrades); and
  • Mid-Missouri (potential low voltages).

“The scope was intentionally left broad to give us the flexibility we need to create these … areas and most efficiently target them,” Bell said. “Some stem from operational issues we see regularly that aren’t showing up in typical planning areas.”

The models are to be developed by the end of July, with preliminary results due in November and a final report in January.

Committee Recommends SPP Intervene in FERC’s NIPSCO Docket

The SSC unanimously endorsed a motion recommending SPP intervene at FERC in an ongoing dispute between MISO and PJM over their interregional planning (EL 13-88).

MISO and PJM have until June 20 to submit a compliance filing responding to an April 21 order in which the commission partially denied and granted a 2013 complaint by Northern Indiana Public Service Co. over the RTOs’ processes. (See MISO, PJM Working to Comply with NIPSCO Order.)

SPP’s options are limited because it did not intervene before the order was issued. Given choices between intervening out-of-time, commenting on MISO’s eventual compliance order or petitioning for a declaratory order, the committee voted to recommend the RTO “intervene out-of-time without comments but justification.”

“It’s really hard to come in at this late stage and ask for standing in the case,” Kelley said. He suggested SPP could intervene once MISO and PJM make their filing and potential Tariff changes.

The vote was partially driven by SPP member ITC Holdings’ intervention in the case. ITC, one of seven intervenors to request a rehearing of the order, said the commission should clarify that its directives to MISO also apply to potential interregional economic projects along the SPP-MISO seam.

FERC directed MISO to lower its interregional project voltage threshold with PJM from 345 kV to 100 kV and remove the $5 million minimum cost requirement. MISO currently has the same 345-kV threshold for economic projects along its seam with SPP, which has limited the ability of the entities to agree on interregional projects.

Staff reminded members that FERC is under no obligation to accept ITC’s request or clarify the applicability issue.

“My analysis leads me to believe … the commissioners probably won’t answer ITC,” SPP attorney Matthew Harward said. “If it grants ITC’s request for clarification, that could potentially impact SPP.”

Harward said he understood that several motions opposing ITC’s request have been filed, but he had yet to review them.

Kelley said MISO staff has told him the RTO is “taking the policy position that these things do not apply” to SPP and MISO and that the order is related only to the MISO-PJM seam.

Harward seemed to agree. “The order is narrowly drawn for the PJM-MISO seam,” he said.

— Tom Kleckner

Posted on

Company Briefs: June 13, 2016

Apple’s newly formed energy subsidiary has filed with FERC to begin selling wholesale power from its solar facilities in California and Nevada (ER16-1887).

Apple Energy, formed on May 20 and headquartered in Delaware, asked FERC last week for market-based rate authority to offer capacity and other services, such as spinning reserves, frequency response and operating reserves, in CAISO.

However, the company also seeks permission to sell in NYISO, MISO, ISO-NE, SPP and PJM, suggesting further expansion. The company asked for approval within 60 days of the filing.

More: 9to5Mac; Tech Times

WPPI Energy Seeking 100 MW of Renewables

WPPI Energy, a Wisconsin public power supplier, said it is looking to secure 100 MW of renewable energy for its companies in Wisconsin, Michigan and Iowa to meet regulatory mandates in those states.

WPPI, which serves 51 municipal electric utilities in the three states, already has several wind projects in development. Its current plan is to sign power purchase agreements stretching 20 years or more, the company said.

More: Milwaukee Journal Sentinel

DCNS Joins Maine Floating Turbine Consortium

French defense contractor DCNS Group has formed a partnership with Maine Aqua Ventus, the University of Maine-led consortium developing a floating offshore wind farm.

Maine Aqua Ventus aims to build a 12-MW wind farm near Monhegan Island in a pilot program supported by the U.S. Department of Energy. The role of DCNS, which builds submarines and naval vessels, is still being defined, according to the consortium.

Frederic Le Lidec, DCNS’s marine renewable energy director, said the company is working on three marine renewable technologies: tidal energy, ocean thermal energy conversion and offshore wind. He said DCNS is offering its services in engineering, construction, installation, maintenance and project management.

More: Portland Press Herald

Shell Chemical to Build Pa. Ethane Cracker Plant

Shell Chemical Appalachia announced plans to build a massive, multibillion-dollar ethane cracker plant near Pittsburgh.

The plant will need 105,000 barrels of ethane a day, produced in the Marcellus and Utica shale fields of Pennsylvania, Ohio and West Virginia. It will break down, or “crack,” that ethane into 1.5 million metric tons of ethylene, a chemical used in the production of plastic, a year.

The complex will receive $1.65 billion in tax credits spread over a quarter century. Pennsylvania officials hope the complex will spur other industries in the area. Shell will begin construction within 18 months on the grounds of a former zinc smelter in Beaver County. While the company wouldn’t give an exact cost of the project, a similar ethane cracker in Lake Charles, La., cost $11 billion.

More: The Philadelphia Inquirer

Exelon to File for 20-year Extension for Peach Bottom

Only days after announcing that it will close two nuclear generating stations in Illinois, and that another in Pennsylvania is at risk, Exelon Generation announced that it will seek a 20-year extension for its Peach Bottom Atomic Power Station in Delta, Pa.

The licenses for the plant’s two reactors expire in 2033 and 2034, but the company said it will file for the extensions in 2018. Reactor license renewals typically take about two years to make their way through the Nuclear Regulatory Commission process.

More: PennLive; Exelon

Wisconsin’s Dairyland Power Inks 98-MW Wind Deal

The Dairyland Power Cooperative has agreed to buy the output of a proposed 98-MW wind farm near Platteville, Wis., nearly tripling the co-op’s wind capacity.

The 49-turbine Quilt Block wind farm is gathering regulatory approval and is scheduled to come online by the end of 2017.

Dairyland’s agreement would increase wind’s contribution to its load from 4.5% to 12.6%. The co-op has a goal to source 18% of its power from wind by 2025.

More: Associated Press

DTE Energy to Retire 8 Coal Units at 3 Plants

DTE Energy will close eight coal-fired units at three Michigan plants in the next seven years.

The Detroit utility said the affected units at its River Rouge, St. Clair and Trenton plants will be retired between 2020 and 2023. The three plants represent a quarter of the company’s total electricity production. The utility said employees impacted by the shutdowns will be offered jobs at its other facilities.

The move will leave DTE with just six coal-fired units of the 17 it had in 2015. Earlier this year, DTE retired three other coal-fired units and said the lost generation would be replaced with wind, solar and natural gas resources.

More: Crain’s Detroit Business

Dominion’s Chesapeake Center Coal Ash Estimate Triples

Dominion Virginia Power has three times as much coal ash stored at the company’s Chesapeake Energy Center near Norfolk than it previously estimated, according to documents received as part of a Sierra Club suit.

Dominion previously estimated the amount of coal ash at the site was about 1 million tons. But the company’s newer estimates say the three impoundments contain about 3 million tons.

The Sierra Club is asking in a civil suit for the company to remove all of the ash from the site to a lined landfill away from the Elizabeth River to prevent heavy metals from leaching into groundwater and into the river. The suit is scheduled to be heard later this month.

More: The Virginian-Pilot

Toyota’s New HQ will Draw 25% Power from Solar

Toyota’s massive new North American headquarters in Plano, Texas, will draw about 25% of its electricity from a 7.73-MW solar facility mounted on three parking garages.

In the project’s first phase, two 2.45-MW systems will be installed by August 2017, with a 2.83-MW system by December 2017. The seven-building campus, which is about halfway finished, is expected to be completed sometime in 2017.

Toyota did not disclose the cost of the facility, one of the largest in the state. The company estimates the entire campus and moving costs for employees will total about $1 billion.

More: The Dallas Morning News

Talen to Run Natural Gas to Montour Plant

Talen Energy is in the process of selecting an entity to construct, own and operate a 15-mile pipeline to bring natural gas to the 1,500-MW Montour plant as part of a project to convert its two coal-fired units to dual-fuel by 2018.

The estimated cost of modifying the plant in north-central Pennsylvania, near the Marcellus Shale natural gas fields, is about $70 million.

“The Montour plant is located in close proximity to one of the largest natural gas formations in the world, the Marcellus shale,” Talen CEO Paul Farr said. “Co-firing the plant to burn natural gas produced in Pennsylvania enables Talen Energy to leverage the strategic location of the plant.”

More: Talen Energy

New Technology is the ‘Uber of Battery Storage’

Solar industry veteran Shihab Kuran has founded a company to offer modular grid-scale lithium-ion battery systems that can be delivered by truck, train or barge.

The Power Edison systems travel in special containers that can be stacked like Legos and shipped according to shifting demand.

“We are the Uber of battery storage,” said Kuran, who also founded solar energy generation company Petra Systems. “We’re going to offer a solution for the duration that it’s needed, and, after that, we’ll take our solution and repurpose that for other applications.”

More: Bloomberg

Cooperative Hires Lightower To Build Fiber Network

The Delaware Electric Cooperative has chosen Lightower Fiber Networks to build a 250-mile, custom fiber network that will provide a secure way for the co-op to communicate with substations and remote advanced electrical equipment.

The project, which connects 28 sites in Delaware, includes the construction of 180 miles of new network.

More: Lightower

Cities to Break Contracts with Indiana Michigan Power

Nearly a dozen cities in Indiana and Michigan have given Indiana Michigan Power the required four-year notice to end their power purchase agreements. The cities, which all belong to the Indiana Michigan Municipal Distributors Association, plan to break their contracts in 2020, six years earlier than the agreements were originally slated to end.

A city administrator in Niles, Mich., estimated that the city is paying 30% more than market price for electricity, while a general manager for Mishawaka Utilities, in Indiana, put the figure at around 20% over market value.

While the cities could individually buy electricity from other utilities, they can also renegotiate a deal with Indiana Michigan Power.

More: Associated Press

Posted on

Public Utility Commission of Texas Briefs

AUSTIN, Texas — The Public Utility Commission of Texas approved a plan for a hybrid above/below-ground transmission line in the City of Frisco (Docket No. 44060). The project was notable for the financial commitment the city offered to bury the majority of the line. (See Texas PUC OKs Undergrounding Tx Line; City Agrees to Foot Cost.)

While the all-underground route would have cost more than $34 million — nearly $29 million more than the all-overhead route the PUC preliminarily approved — the city has agreed to pay approximately $13 million of the extra cost to have the lines buried in conjunction with an upcoming road-widening and waterline-installation project.

The cost savings of coordinating the projects was factored into the city’s calculations, along with other implications, such as where the project will be sited. The city contended that Brazos Electric Cooperative, the utility overseeing the project, would have had to pay for the right of way, but said it would donate it if the line was sited underground. This, along with some design modifications, brought the cost difference to approximately $4.3 million.

Briefs for ‘Precedential’ Decision

Commissioners called for parties involved in a substation-siting dispute to provide briefs on whether the PUC has jurisdiction in the case (Docket No. 45175). The Colony, a city near Dallas, is arguing that it has jurisdiction under the state’s Public Utility Regulatory Act to determine where the station can go. The local electric co-ops — Brazos and Denton County Electric — believe the PUC has authority under a different section of the same law.

Public Utility Commission of Texas
From left to right, Texas Public Utility Commissioners Kenneth W. Anderson, Jr., Donna L. Nelson and Brandy Marty Marquez consider docket items at last week’s monthly open meeting. © RTO Insider

Chairman Donna L. Nelson said the call for briefs in what she called a potentially “precedential” case was very wide to “get to the real heart of the conflict.”

Commissioner Kenneth W. Anderson Jr. said the commissioners gain much more insight from back-and-forth replies to other briefs, where the parties tend to “savage” each other.

‘More Meat’ Needed for New Interconnection Rule

The commission also adopted a rule to comply with several statutes that affect the paperwork necessary to tie into ERCOT’s grid (Project No. 45124). However, Anderson requested that, following the final approval, PUC staff open a new rulemaking process “to clarify the gaps that the statute doesn’t cover.” He said commission rules should delineate, among other things from the statute, what ERCOT should study to meet its need and reliability criteria, the impact on ERCOT’s market and the process to receive approval for a DC tie into the system.

All of these could have unforeseen consequences. For example, commenters pointed out that ERCOT’s handling of DC ties could — if too broadly defined — affect ERCOT’s independence from FERC jurisdiction.

“We need to put a little more meat on the bones of this rule because it’s not like the normal transmission asset,” he said.

‘Deceptive’ Offers on Customer-Choice Website

Saying that she continues to be “bothered” by “deceptive” offers on the website customers use to choose a power generator, Nelson announced a stakeholder meeting in her office June 21 to address the issue (Project No. 45730).

“Sometimes, I think things move a little faster when a commissioner gets involved,” she said. “The Power to Choose website kind of needs some work right now. The whole concept of choice doesn’t work if customers aren’t educated about what they’re buying.”

Anderson said he’s still “convinced” of the necessity of the website and that the only questions are exactly what might change. He said he uses it to shop and has always paid less than the last regulated rate.

The commissioners cautioned retail energy providers against putting out offers that are significantly below cost or whose rate requires meeting unreasonably specific consumption targets. However, they also disapproved of requiring retail electric providers to create standardized offers, saying those would be anti-competitive.

Though the site isn’t perfect, Commissioner Brandy Marty Marquez urged consumers who are overwhelmed by the shopping process to request a tutorial from PUC staff, who find it “one of the most exciting things” to do, she said.

‘Shock’ over SPP Z2 Billing Plans

Marquez said it was “shocking” that SPP plans to request repayment over 10 months of transmission upgrades that were approved over a period of more than eight years. (See related story, Z2 Project Faces Further Hurdles, Possible Delay.)

The commissioners said they were concerned for ratepayers shouldering the burden of the repayments over such a short period.

Additional Actions

The commission also:

  • Approved applications by American Electric Power’s Texas affiliates, Texas New Mexico Power, Oncor, CenterPoint Energy and Sharyland Utilities to adjust their energy-efficiency cost-recovery factors.
  • Returned to an administrative law judge the application by Luminant and Oncor to transfer ownership and administration of the decommissioning trust for Comanche Peak Nuclear Power Plant. The application was based on a plan that is being changed and resubmitted by the bankruptcy court overseeing the decommissioning process, so it needed to be revised.
  • Approved publishing a proposed rule on how distributed generation facilities can connect to the grid (Project No. 45078). The proposal would allow interconnection agreements to include the end-use customer, the owner of the DG facility, an owner of rights to energy produced from the DG facility or the owner of the premises at which the DG facility is located.

– Rory Sweeney

Posted on

Federal Briefs

The Supreme Court on Monday declined to review a D.C. Circuit Court of Appeals ruling allowing EPA to continue enforcing its Mercury and Air Toxics Standards (MATS) while the agency complies with a 2015 high court ruling to address procedural issues (15-1152, Michigan, et al. V. EPA, et al.).

In the 2015 decision, the court found that EPA had failed to take costs into consideration when deciding whether the MATS rule was “appropriate and necessary” under the Clean Air Act. The court allowed EPA to continue enforcing the rule, however, while the agency addressed the court’s concerns. The agency responded with a supplemental finding, saying the cost review did not change its opinion on the need for the rule and proposing to leave MATS unchanged.

Several states asked the D.C. Circuit to require the agency to conduct a new rulemaking, a request the court rejected in December. The litigation is largely moot: Most power plants covered by the rule complied or retired by the deadline of April 2015. Some plants received a one-year extension on the deadline, which has also passed.

More: POWER Magazine

IEA Says Renewable Subsidies Still Needed

A report by the International Energy Agency says that subsidies are still needed to ensure continued growth of renewable energy.

iea(iea)Government subsidies make renewable energy projects less risky investments. But the IEA warns that as the energy generated by renewables becomes less expensive, governments may look to scale back the subsidies.

“As we enter this new phase, the question becomes what can the policymaker do to maintain bankability [and] reduce the risk of investments in generation without just throwing subsidies out, which isn’t where anyone wants to be,” said Toby Couture, director at the German renewable energy consultancy E3 Analytics and an author of IEA’s report.

More: Greentech Media

Iceland Testing New Carbon Capture Method

carbfix(carbfix)Scientists working in Iceland are testing a new method of carbon capture and sequestration, injecting CO2 from a geothermal plant into basalt to form calcite, theoretically locking the gas in the ground permanently.

CarbFix, as the project is known, has so far resulted in about 95% of the CO2 injected being converted to calcite. So much calcite was formed by the testing process that a pump used to test the water became clogged with the mineral. The scientists found that the calcite formed in less than two years.

Iceland is practically all basalt, making it an ideal location to test the new method. The project is being conducted in partnership with the Icelandic capital’s municipal utility, Reykjavik Energy, at a plant about 15 miles east of the city. Work is being done now to figure out a way to scale the project up to industrial sizes and to find other suitable locations with enough basalt.

More: The New York Times

Report: US Solar Installations To Double in Coming Year

gtmresearch(gtm)Developers rushing to meet a deadline for a federal solar tax credit are driving U.S. solar installations to nearly double the total capacity in 2016, according to a report by GTM Research. By the end of the year, 14.5 GW of solar capacity will be online, the report says.

Solar installations rose 24% in the first quarter this year, about 64% of all new electric generation capacity during that period, according to the report.

Most of the utility-scale projects were pushed through on expectation of the year-end solar tax credit expiration. The credit was extended for five more years, however. The extension will spur more than 20 GW of additional solar capacity by 2021, GTM said, though the utility-scale market is expected to contract next year and in 2018.

More: Reuters

FERC Grants Rehearing On NJ Pipeline Project

transco(transco)FERC has granted the request for new hearings on Transco’s Garden State Expansion project after a group of municipalities said the company failed to give proper notice of meetings and didn’t meet environmental requirements.

Although not a large project — it involves a new compressor station, upgrades to another substation and upgrading some existing pipeline — the municipalities and environmentalists called it a win.

“Anytime we get FERC to reopen a docket and have a rehearing is an environmental victory,” said Jeff Tittel, New Jersey Sierra Club director. “FERC almost never grants a rehearing and the fact that they did it shows that there were significant problems in the approval of Transco’s application.”

More: Planet Princeton

Annual NRC Meeting on Indian Point Gets Heated

indianpoint(nrc)The Nuclear Regulatory Commission held its annual public meeting on the operation of Entergy’s Indian Point nuclear station, and things got heated, with members of the public telling the commission it is failing in its job to keep the plant operating safely.

“You don’t care about our lives, you don’t care about our future,” said Susan Shapiro, who identified herself as a member of the Indian Point Safe Energy Coalition, a protest group. “All you care about is how you are going to grease the pockets of Entergy.”

David Lew, an NRC deputy administrator overseeing the northeast region, said Indian Point is operating within guidelines. “Our overall conclusion is that Indian Point operates safely and will continue to operate safely,” he said.

More: Westchester County Business Journal

Talen Reports Leaks At Susquehanna Plant

talensusquehanna(talen)Talen Energy, operator of the Susquehanna nuclear plant in Pennsylvania, reported the discovery of two small leaks of radioactive water while shutting Unit 1 down last week for regular maintenance.

Staff discovered one leak inside the containment structure and a second leak in lines leading to instrumentation sections of the unit. Both leaks were contained and there was no danger, according to the report made to the Nuclear Regulatory Commission.

“When the plant is operating, there are certain areas you can’t access when it’s in power,” said spokesman Todd L. Martin. “When we did the downpower to address the initial leak, that’s when we found this additional leakage, and that prompted the second notification.”

More: The Citizens’ Voice

Posted on

Berkshire Market-Based Sales Restricted in 4 Western BAAs

By Robert Mullin

FERC last week revoked authorization for Berkshire Hathaway Energy subsidiaries to sell wholesale power at market-based rates in four neighboring balancing authority areas in the West.

The commission ruled that Berkshire failed to prove that its affiliates — which include PacifiCorp, NV Energy and 19 other generating entities — do not exercise horizontal market power in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas (ER10-2475, et al.).

“In the absence of reliable delivered price test (DPT) analyses rebutting the presumption of market power, we find that the continuation of the Berkshire [subsidiaries’] market-based rate authority in these four balancing authority areas is not just and reasonable,” the commission said.

Western Interconnection Subregions & Balancing Authorities (WECC)
Berkshire Hathaway Energy’s subsidiaries will be restricted from selling at market-based rates in the PACE, PACW, NWMT, and IPCO areas represented on the map.

FERC ordered the companies to file revised tariffs limiting their market-based sales to regions outside the four areas within 30 days. The companies must also issue refunds for the period between January 9, 2015, and April 9, 2016.

The decision left intact Berkshire market-based rate authority in the Arizona Public Service, Bonneville Power Administration, Los Angeles Department of Water and Power, Western Area Power Administration Colorado-Missouri and WAPA Lower Colorado balancing authority areas, as well as in CAISO.

Berkshire companies are already prohibited from selling power at market-based rates in the NV Energy area covering most of Nevada.

FERC’s ruling marks the second such setback for Berkshire in less than a month. In May, the commission declined to rehear a 2015 decision that prohibits PacifiCorp and NV Energy from offering energy into the Western Energy Imbalance Market (EIM) at prices above default energy bids because of concerns about the companies’ combined market power. (See Berkshire Denied Rehearing on EIM Market Power.)

The June 9 order stems from Berkshire’s 2013 acquisition of NV Energy, which put Warren Buffett’s energy conglomerate in control of more than 19 GW of generation serving states throughout the western U.S. In light of the acquisition, the commission instituted a Section 206 proceeding requiring the Berkshire companies to submit evidence that their market-based rate authority remained valid in the four areas in question.

While the Berkshire companies failed the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power in the four areas, FERC policy allows a power supplier to rebut that presumption by performing a more thorough DPT analysis. The DPT factors in native load commitments to determine a supplier’s “available economic capacity” — energy available for offer in the open market — over 10 different seasons and load conditions. The analysis must also consider the load commitments for and available supply from other generators in the region.

FERC’s decision to revoke Berkshire’s market-based rate authority ultimately rested on what the commission called a “flawed” DPT analysis from the company. The commission focused in particular on Berkshire’s failure to calculate unique season and load levels for each of the four areas, instead relying on assumptions based on data for only the PACE area.

One example cited by the commission: “In the Idaho Power balancing authority area, Idaho Power would likely not be a competing supplier in certain season/load levels in the [available economic capacity] analysis, even though it is listed as having the most competing capacity in many of the season/load levels.

“The Berkshire [companies] are attempting to demonstrate that they do not have market power in four different balancing authority areas,” the commission continued. “In order to do so, the DPT analyses submitted by the Berkshire [companies] should have used inputs, assumptions and facts appropriate to the unique characteristics of each balancing authority area when studying that particular area.”

As a result of the decision, the Berkshire companies must each submit tariff revisions providing for default cost-based rates for the PACE, PACW, Idaho Power and NorthWestern areas — or inform the commission of their intention to use any cost-based tariff currently on file.

PacifiCorp — the largest Berkshire entity affected by the ruling — told RTO Insider that it continues to review the order but expects “limited impact” because of the small number of transactions involved.

“The bulk of PacifiCorp’s wholesale sales occur at trading hubs that are outside the areas affected by the order, or within the Energy Imbalance Market, which is also not impacted by the order,” spokesman Bob Gravely said.

Asked whether the ruling would strengthen the case for PacifiCorp to join CAISO in an effort to reduce market power concerns, Gravely said, “This ruling shouldn’t impact one way or the other the decision to join a regional ISO. Issues such as governance and ensuring overall net benefits for customers are what will ultimately drive that decision.”

Posted on

After Years of Questions, Interconnection Customers Await Answers

By Rich Heidorn Jr.

WASHINGTON — FERC has been asking questions about improving the transmission interconnection process for eight years.

transmission interconnection customers
Quinn © RTO Insider

“There will be a point where we stop asking questions,” FERC’s Arnie Quinn promised during a panel discussion at the Energy Bar Association’s Annual Meeting last week.

That point will come after the commission reviews the transcript of last month’s technical conference on the subject and the post-conference comments it is now soliciting.

The commission’s questions started in 2008, when it asked the RTOs to make proposals to reduce interconnection backlogs (AD08-2). The grid operators offered a number of changes, including clustering interconnection studies by location and establishing development milestones to weed out projects not progressing toward commercial development.

But the changes haven’t ended developers’ complaints about study delays or the difficulty in predicting interconnection costs. At the technical conference, transmission operators countered that the delays are caused by the high number of speculative interconnection requests, which force them to conduct restudies when a project drops out of the queue. (See Generators, Tx Operators Spar over Interconnection Processes Before FERC.)

Post-conference comments are due June 20 (RM16-12, RM15-21).

After that, the commission could respond with a prescriptive rulemaking, a policy statement — which wouldn’t require transmission operators to make any changes — or a hybrid of the two, said Quinn, director of FERC’s Office of Energy Policy and Innovation.

“The difficulty with this topic … is it’s fairly straightforward to define the problem,” Quinn said. “Identifying the solutions that are going to work everyplace — that’s the harder nut to crack.”

Incremental, Comprehensive Changes Sought

Last month’s conference was called in response to a rulemaking request by the American Wind Energy Association, which argued that existing interconnection rules are outdated and discriminatory.

Moore © RTO Insider - transmission interconnection customers
Moore © RTO Insider

Panel moderator John Moore, of the Natural Resources Defense Council, opened the EBA session last week by quoting from Invenergy’s testimony at the conference, in which the company related its experiences on the length of the interconnection processes: SPP (one year); PJM (two years); CAISO (two and a half years); MISO (“has seldom taken less than three years”); and NYISO (as long as six to seven years). “An interconnection process lasting three years or more can kill even the most serious of projects,” Invenergy’s Kris Zadlo said.

Quinn said he concluded from the conference testimony that developers are seeking both incremental improvements — including more access to models and the ability to self-construct interconnection facilities — and more comprehensive changes.

The comprehensive proposals are more controversial, Quinn said, citing a call for closer coordination between the transmission planning and the interconnection processes. “Instead of serially studying a bunch of projects over time, just identify an area on the transmission system where you’ll need some upgrades. Using the transmission planning process to do that might smooth the interconnection process,” Quinn explained.

The controversy? “Transmission is usually paid for by load; interconnection upgrades are typically paid for by the interconnection customers. So that can look like a cost shift, and — especially where the states are involved — they might want a say in the degree to which that cost shift occurs,” Quinn continued.

Another suggestion is to cap interconnection cost estimates at an early stage in the interconnection process, as CAISO is doing. “If the interconnection customer can get some information on cost that can feel firm, the interconnection customer can keep moving on,” Quinn said.

Panelist Mason Emnett, a federal regulatory attorney for NextEra Energy, had his own wish list. He said he would like RTOs to provide developers with information on their overloaded facilities. “Our transmission engineers can use that to go back to developers to give them a reality check and say, ‘This is what you’re facing.’”

Storage

Emnett also called for refinements in the modeling of storage resources. “RTOs generally consider the storage to be operating at full output — full discharge — at the worst time of the system, which generally is not going to be the time that the storage asset is operating that way.”

But he said storage doesn’t need an entirely separate process, either. “Nobody really loves [the current process]. The TOs don’t, the RTOs don’t, the generators don’t. But I’m not sure how you come up with a different one for storage because the question that’s being answered is largely the same: Are you changing the nature of the flows on the system? And what [is] the technical configuration of the equipment that you’re interconnecting and how does that interact with other things?”

More Flexibility Needed

Emnett © RTO Insider</em<
Emnett © RTO Insider

Emnett said RTOs should provide more flexibility, praising MISO’s “net zero” policy.

“We’ve put some batteries on existing wind sites that had excess interconnection rights so that interconnection rights had already been studied at a certain level but they weren’t being fully utilized. In our mind, why can’t you just stick another resource on? You don’t have to go through the full study because all you’re using is something you’ve already got.”

He also cited PJM policy allowing interconnection customers to install more capacity than it has in injection rights. The interconnection service agreement requires that the customer limit its output. “If you burn down my wires you are responsible for everything,” Emnett said, summarizing.

Even if it requires a special protection scheme, Emnett said, “it’s going to be, in all likelihood, less expensive than upgrades and able to be implemented much more timely than the two and a half years to get a 10-MW storage project” approved.

Standardizing the Process

Tim-Aliff,-MISO-web
Aliff © RTO Insider

The panel also discussed whether the commission should order more standardization in the grid operators’ interconnection processes.

“I hope FERC will allow regional differences,” said panelist Tim Aliff, MISO’s director of reliability planning. He noted the RTO operates in 13 states. “So we have 13 different opinions of how things should be done.”

Aliff also responded to Invenergy’s description of interconnection timelines. “I do take exception to the [assertion that MISO takes] ‘no less than three years’ because it depends on where you are in our footprint,” he said.

In March, FERC rejected the RTO’s proposed changes to its queue process, saying they assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). The commission also said a proposed milestone payment could create barriers to entry for smaller developers. (See MISO Queue Changes on Hold Pending Technical Conference.)

Aliff said that in addition to working on revisions to its proposal, MISO is considering how it can accommodate additional wind growth.

In 2011, MISO approved multi-value projects (MVPs) designed to serve 26 GW of wind. The RTO has 15 GW of installed wind and another 10 GW in the queue.

“So if all of this generation were to interconnect and actually start generating, then we would be at the capacity or close to the capacity of our MVPs,” he said. “So now we’re kicking off the process to say what’s the next step in this? We may or may not come out with MVP-like projects, but we want to get ahead of [the demand] again. We want to look at what the Clean Power Plan is going to do.”